1. Field of the Invention
This invention relates to contacting a natural gas stream with a preferential physical solvent. It more specifically relates to separating and recovering ethane, propane, and higher boiling hydrocarbons from natural gas streams and especially relates to rejuvenation of conventional lean oil absorption plants which recover hydrocarbons from a natural gas stream. It further relates to specific preferential physical solvents for recovery of selected hydrocarbons from a natural gas stream.
2. Review of the Prior Art
Hydrocarbons must often be recovered from such natural gas streams as natural gas, alkylates, reformates, and the like. Many recovery processes are available, but countercurrently contacting the upwardly flowing gas stream with a downwardly flowing liquid under conditions furnishing high interfacial surface area is often a preferred recovery process, generally known as absorption and herein identified as extraction when highly preferential physical solvents are used.
Most physical solvents show some preference among hydrocarbons in a mixture thereof. In other words, they have greater solvency, perhaps because of a stronger physical attraction, for one or more hydrocarbons in such a mixture. This preference is measured by the absorption principle, leading to an alpha or relative volatility. Most of the commonly used lean oils, for example, have relative volatilities of methane over ethane of slightly less than 5.
Each gaseous hydrocarbon goes into solution in the lean oil in inverse proportion to its vapor pressure, the lower the vapor pressure, the greater the tendency to dissolve, each component being concentrated as an "absorbate" dissolved in the lean oil. Absorption can also be increased within an absorption column by an increased flow rate of lean oil, by decreased temperature because the vapor pressures of the absorbed compounds are lowered, and by increased pressure because more absorbate is dissolved by raising the partial pressures of the absorbates.
Lean oils are usually high-boiling gasoline fractions or distillate-fuel stocks like kerosene which are chosen according to absorption capacity, lean oil loss, viscosity, and stability. Because absorption capacities of liquids are molal functions, lighter oils, which have lower molecular weights, have high absorption capacities on a weight basis. Any hydrocarbon oil has a greater capacity to absorb chemically similar materials, and most of the vapors to be absorbed from a natural gas are paraffinic; therefore, paraffinic lean oils are preferable for a natural gas. Loss of lean oil, which is inversely proportional to the molecular weight of the lean oil, must be balanced against the greater absorption capacity of a lower molecular weight oil.
The rate of mass transfer in absorption depends principally on the molecular weight and relative viscosity of the lean oil. Because higher rates of transfer are obtained when using less viscous, lower molecular weight oils, their use minimizes the tray packing requirements for a given operation.
It is pertinent to the invention that lean oils have been used for at least about 60 years in absorption plants which recover C.sub.4 + hydrocarbons from natural gas streams. It is highly pertinent to this invention that the lean oils are non-selective for lighter hydrocarbons, such as methane, ethane, and propane, which represent most of a natural gas stream. The higher partial pressure in the absorption column cause relatively large amounts of methane to be absorbed, thereby making the separation of ethane and propane from methane quite difficult and expensive. Due to the market demand for lighter hydrocarbons and the lack of selectivity of lean oils for such components, the absorption process has been gradually replaced by improved processes known as the refrigerated oil absorption, simple refrigeration, cascaded refrigeration, Joule-Thompson, and cryogenic expander processes. The extractive flashing embodiment of the Mehra Process, as disclosed in U.S. Pat. Nos. 4,421,535, 4,511,381, and 4,526,594, utilizes preferential physical solvents for extracting selected amounts of C.sub.2 -C.sub.4 hydrocarbons and all C.sub.5 +hydrocarbons from a natural gas by using the steps of flashing, recycling of C.sub.1 -rich flashed gases, and compression, cooling, and condensing of C.sub.1 -lean flashed gases, followed by demethanizing the condensate to produce a natural gas liquid (NGL) product and an overhead gas stream which is recycled to the extraction step. Typical recoveries for these processes are compared in Table I.
TABLE I ______________________________________ COMPARISON OF TYPICAL LIQUID RECOVERIES ETH- PRO- BU- GAS- ANE PANE TANES OLINE EXTRACTION (%) (%) (%) (%) ______________________________________ ABSORPTION 5 25 75 87 REFRIGERATED 15 75 90 95 ABSORPTION SIMPLE 25 55 93 97 REFRIGERATION CASCADED 70 85 95 100 REFRIGERATION JOULE-THOMPSON 70 90 97 100 EXPANSION TURBO-EXPANDER 85 97 100 100 MEHRA PROCESS 2-90 2-99 2-100 2-100 ______________________________________
In summary, the oil absorption, refrigerated oil absorption, simple refrigeration, and cascaded refrigeration processes operate at the pipeline pressures, generally without letting down the gas pressure, but the recovery of desirable liquids (ethane plus heavier components) is poor, with the exception of the cascaded refrigeration process which has extremely high operating costs but achieves good ethane and propane recoveries. The Joule-Thompson and the cryogenic turboexpander processes achieve high ethane recoveries by letting down the pressure of the entire inlet gas, which is primarily ( methane (typically 80-85%), but recompression of most of the inlet gas is quite expensive.
As the demand for C.sub.2 -C.sub.4 hydrocarbons has increased over the years, the oil absorption plants have often been redesigned to include refrigeration, thereby becoming refrigerated absorption plants, because lower temperatures enable the lean oil to absorb larger quantities of gaseous hydrocarbons. The simple refrigeration process, which typically recovers 80% of the propane, also typically requires the recovery of 35% of the ethane. In order to boost propane recovery to the 95+% level, cascaded refrigeration, Joule-Thompson, or cryogenic turbo-expander processes have to be used while simultaneously boosting the ethane recovery to 70+% at a considerably larger capital investment.
Of the total of 814 natural gas plants presently in the United States according to Oil and Gas Journal, Jul. 15, 1985, 6% are simple absorber plants and 25% are refrigerated absorption plants. Absorber plants have a capacity of about 5 billion standard cubic feet of gas per day but treat about 2 billion standard cubic feet of gas per day, and refrigerated lean oil absorber plants have a capacity of about 22 billion standard cubic feet of gas per day but treat slightly over 12 billion standard cubic feet of gas per day.
Many of these plants have also experienced a natural decline in gas availability due to their age. Moreover, the reduced volumes and inefficient recoveries for lighter hydrocarbons, such as ethane and propane, have adversely affected their economics. The availability of propane within the United States from all sources falls short of propane demand, thereby requiring propane to be imported in the reported quantities of 66,000 barrels per day in 1985. Consequently, there is a need to improve the economics of such plants by increasing the recovery of C.sub.2 -C.sub.4 hydrocarbons that are present in the locally available gas streams.
At many locations, outmoded lean oil plants have been abandoned and are idle and rusting or are being replaced with new turbo-expander plants being built alongside them at substantial capital expenditures. Such lean oil absorber plants are tremendously varied in their processes; yet they have basic similarities, and each has the same basic need for recovering additional quantities of C.sub.3 +hydrocarbons and particularly of propane itself in order to retain profitability and avoid abandonment and/or replacement with a more modern plant. There is accordingly a need for a process that can rejuvenate such old plants, without requiring large investments for modernization thereof, by recovery of economically large amounts of C.sub.3 + hydrocarbons and particularly of propane itself from the same flow of incoming natural gas. There is further a need to recover economically worthwhile quantities of ethane at some locations.
These lean oil absorber plants generally utilize steps of absorption, distillation and/or flashing for the purpose of excluding undesirable components. These steps are generally followed by regeneration of the absorption oil and recycling it to the absorption step. Then the hydrocarbons are separated from the absorption oil. Nevertheless, as varied as these plants are, their basic steps and apparatuses can be utilized.
Most of the lean oil plants were built during 1940-1960 when the demand for propane and ethane as petrochemical feedstocks was relatively slack, so that the installed equipment is presently not capable of high recoveries of these hydrocarbons. Theoretically, if there were no equipment size limitations, any lean oil absorption plant could recover hydrocarbon components by simply increasing the flowrate of lean oil. But plant design imposes basic limitations; for example, increasing the lean oil flow rate could flood an absorption column and, immediately before flooding, cause the downstream equipment to handle laroe quantities of methane, since lean oils are not selective, and the absorption of components occurs in proportion to their partial pressure. Moreover, practical economics in the market place does not permit equipment to be replaced to eliminate bottlenecks. Therefore, there is a need to improve the hydrocarbon component recoveries without abandoning the existing equipment or resorting to such expensive alternatives as installing the necessary equipment associated with the other processes of cascade refrigeration, Joule Thompson, or Cryogenic turbo expander processes.
It is also important to note that when these plants were originally built, the objective was to make the gas transportable by removing most of the butanes and the gasoline components of the natural gas stream. Thus, the emphasis then was to size the equipment so that it would substantially recover C.sub.4 's and heavier components. However, along with such recoveries of C.sub.4 +, some propane was also recovered because the lean oils were not selective.
In lean oil absorber plants which conventionally deliver residue gas to pipelines at 300-1300 psig, the inlet gas, which is in most cases at about 5 to 150 psig, is compressed in multiple stages to the operating pressure of the absorber. In most plants, the operating pressure of the absorber is selected by the residue gas delivery pressure in order to take advantage of the higher partial pressures for the absorption processes.
It is another characteristic of lean oil absorber plants that most of the lean oils are physical solvents, but they are not preferential physical solvents according to the definition thereof in the parent applications for the Mehra Process. An interesting phenomenon associated with a preferential physical solvent, as defined by relative volatility and loading factor or by preference factor, is that the relative volatility or selectivity of each hydrocarbon being absorbed into the solvent tends to change in response to the characteristics of the solvent. The relative volatility of C.sub.1 over C.sub.2 in the presence of most lean oils is essentially the same as if the lean oil were absent, i.e. if the selectivity were slightly less than 5.0. There would accordingly be a potential benefit if a preferential physical solvent could be substituted for lean oil in the absorber plants used for processing natural gas where there might be a possibility of changing the absorption behavior in the absorber column and thereby improving the economics.
The lean oils as used in the existing lean oil absorbers are essentially paraffinic base and form an essentially homogeneous mixture of paraffinic hydrocarbons which are of substantially higher molecular weight than the normal hydrocarbons present in a natural gas stream. Therefore they do not show any tendency to change the selectivity characteristics of the hydrocarbon components of the natural gases being treated.
U.S. Pat. No. 2,290,957 describes a process for recovering volatile hydrocarbons, such as propane, butane, and a natural gasoline, from gases containing these components by using two absorption media, one absorbent being lighter or more volatile than the other and being used to contact the gas in the first absorber and the heavier absorbent being used in a second absorber to contact the gas from the light absorbent. The light absorbent is made up of a relatively pure fraction lighter than the finished gasoline. In the first absorber, the light absorbent contains none or at least very little of any constituent lighter than pentane. In the second absorber, the gas is contacted with a heavy absorbent such as mineral seal oil which picks up the light absorbent coming over in the gas from the first absorbent. The gas leaving the second absorber is composed of methane and ethane, with only traces of heavier components, and leaves as residue gas.
U.S. Pat. No. 2,321,666 relates to an absorption refrigeration process in which the scrubbing temperatures are as low as about -100.degree. C. and the scrubbing pressures are less than the critical pressure of methane (672 psia). A C.sub.3 -hydrocarbon liquid is the preferred scrubbing liquid when a C.sub.2 -hydrocarbon component is to be separated from methane in a normally gaseous mixture.
U.S. Pat. No. 2,620,895 describes a process in which selected heavy constituents are separated from a mixture of natural gases by chilling an aqueous solution of 40% diethylene glycol which dehydrates and chills the gas mixture. A cold lean oil then scrubs the cold, dry gas mixture to remove its heavy constituents. The rich oil is sent to a rectifier or distillation column and then to a chiller.
U.S. Pat. No. 3,236,029 describes a process for separation and recovery of condensable hydrocarbons from natural gas by feeding a lean absorption oil, such as a mineral seal oil, to the upper portion of an absorption column. The overhead stream is residue gas. Rich absorption oil is removed from the bottom of the column and flashed to remove methane. The flashed oil is heated and passed through the upper portion of the stripping section of a de-ethanizing absorber, the bottom portion of which is a stripper having a reboiler.
The extractive flashing embodiment of the Mehra Process, as disclosed in U.S. Pat. Nos. 4,421,535, 4,511,381, and 4,526,594, which are incorporated herein by reference, utilizes preferential physical solvents for the purpose of recovering natural gas liquids from natural gas streams by extracting the natural gas streams with a preferential physical solvent, flashing the rich solvent, and compressing, cooling, and condensing at least one C.sub.1 -lean vapor fraction which is then demethanized to produce the gas liquids. This embodiment of the Mehra Process thus combines the advantages of the higher-pressure absorption processes by selectively extracting and letting down the pressure of essentially the desired components, thereby reducing the compression of undesired components, such as methane, while achieving high levels of component recovery in a flexible manner. The Mehra Process is capable of overcoming the disadvantages of non-selectivity of common lean oils for lighter hydrocarbons, such as ethane and propane.
The minimum qualifications for the preferential physical solvent utilized in the extractive flashing embodiment of the Mehra Process has a minimum relative volatility of methane over ethane of 5.0 (thereby defining its improved selectivity toward ethane over methane) and a minimum solubility of 0.25 standard cubic foot per gallon (SCF/gal) of the solvent (thereby defining its hydrocarbon loading capacity). Dimethyl ether of polyethylene glycol, having respective values of 6.4 and 1.0, is identified as the preferred preferential physical solvent.
Therefore, it is the combination of improved selectivity towards ethane and the hydrocarbon loading capacity of dimethyl ether of polyethylene glycol that makes it a superior solvent for selectively extracting and recovering the components of a natural gas stream that are heavier than methane. This combination also enables solvent flow rate variations and flashing-pressure variations to be particularly useful for flexibly producing liquid products having selected hydrocarbon compositions. A mixture of dimethyl ethers of polyethylene glycol, having a molecular weight of 146 to 476 and containing 3-10 ethylene units, for example, is a highly satisfactory solvent.
While such solvents are satisfactory for the extractive flashing embodiment of the Mehra Process, they are subject to possible further po1ymerization and/or thermal degradation if cyclically flowing through a unit operation requiring heating, such as distillation, at the process temperatures used for separation of mixtures into useful fractions or components within equipment used in existing lean oil absorption facilities. There is, therefore, a need for other solvents that are not subject to these limitations.
U.S. Pat. No. 2,846,443 teaches the addition of small quantities of organic compounds, only slightly soluble in water and comprising aromatic hydrocarbons which assist in flocculation of the colloidal suspensions of the polymers derived from acetylene, to special selective solvents, miscible in water, such as dimethylformamide, gamma-butyrolactone, and N-methylpyrrolidone. These aromatic hydrocarbons include toluene, benzene, and homologues of benzene and chlorinated hydrocarbons such as trichloroethylene.
U.S. Pat. No. 3,280,206 relates to liquid-liquid extraction with inert organic solvents such as carbon tetrachloride, chloroform, tetrahydrofuran, diethylene glycol dimethylether, and benzenoid hydrocarbons which are free of olefinic and acetylenic unsaturation and boil at a temperature which is below the boiling point of the high boiler, such as benzene, toluene, ethylbenzene, xylenes, mesitylene, biphenyl, the lower alkyl biphenyls, and the terphenyls, in order to remove high boiling polyphenyls which have been formed by exposure to heat and/or ionizing radiation of organic coolants and coolant-moderators in nuclear reactors.
U.S. Pat. No. 3,349,145 teaches an improvement in a process for the catalytic hydrodealkylation of an alkyl aromatic hydrocarbon feed in the presence of an excess of hydrogen. The process comprises withdrawing from a source of impure hydrogen a hydrogen-rich gas comprising C.sub.1 -C.sub.5 paraffins and countercurrently scrubbing the gas, which is under a pressure of 200-1000 p.s.i.g. and at a temperature below 200.degree. F., with a liquid absorbent consisting essentially of a mixture of C.sub.9 + aromatic hydrocarbons, thereby absorbing a substantial portion of the paraffins in the absorbent. The aromatic hydrocarbons utilized as the liquid absorbent may comprise, either in pure form or in admiXture with other aromatics, xylenes and higher polyalkyl benzees such as trimethylbenzenes and tetramethylbenzenes. However, alkyl subsituted mononuclear aromatics having more than 3 methyl groups per nucleus or having an alkyl group containing more than 3 carbon atoms are less preferred because of their higher hydrogen equivalency. When the crude hydrogen contains C.sub.6, C.sub.7, or C.sub.8 paraffins, a preferred absorbent comprises a C.sub.9 + aromatic hydrocarbon, either in pure form or admixed with other C.sub.9 + aromatics, such as propylbenzene, isopropylbenzene, pseudocumene, and mesitylene.
Preferential physical solvents are used in an extractive stripping embodiment of the Mehra Process, as disclosed in Ser. No. 784,566 and Ser. No. 808,463. These solvents are rich in C.sub.8 -C.sub.10 aromatic compounds having methyl, ethyl, or propyl alphatic groups and selective for ethane and heavier hydrocarbon components of the gas stream such that: (a) the relative volatility of methane over ethane is at least 5.0 and the hydrocarbon loading capacity, defined as solubility of ethane in solvent, is at least 0.25 standard cubic feet of ethane per gallon cf solvent, or (b) the preferential factor, determind by the multiplication of relative volatility of methane over thane by the solubility of ethane in solvent, in SCF of ethane per gallon of solvent, is at least 1.25.
Many lean oil absorption plant utilize stripping, such as with a reboiler, for removing absorbed hydrocarbons from the rich oil. An example is taught in U.S. Pat. No. 2,516,507 which discloses process for absorbing C.sub.1 -C.sub.3 hydrocarbons from a gaseous mixture thereof that is fed to the midsection of an absorption column which also receives a stream of absorption oil (a mixture of C.sub.5 -C.sub.7 hydrocarbons) at its top. The residue gas is methane. A portion of the C.sub.1 -+C.sub.3 gases are withdrawn as a sidestream, but all of the C.sub.3 hydrocarbons is absorbed in the oil below the withdrawal line within the primary absorption zone, wherein the oil is heated by a reboiler to drive off the absorbed C.sub.2 hydrocarbons.
U.S. Pat. No. 2,868,326 discloses a process which comprises absorption of a natural gas with absorption oil in a column having a reboiler. Its bottoms are fed to the midsection of a distillation column functioning as a depropanizer. Its overhead condensate is partially refluxed and partially fed to the midsection of a second distillation column functioning as a de-ethanizer.
U.S. Pat. No. 2,938,865 shows a de-ethanizing absorber column having an absorption zone in its upper part, a stripping zone in its lower part, an external reboiler at its bottom, a feed line for absorption oil into the upper portion of the column, and a feed line for a compressed, wet gas into its intermediate portion, between the stripping and absorption zones.
An additional problem that arises in processes using solvents is caued by the presence of small amounts of cyclic hydrocarbons in the gas stream when the cyclic compounds have a higher boiling point (i.e., a higher molecular weight) than the solvent. Under such circumstances, the cyclic compounds tend to build up in the solvent and cause the solvent to lose its preferential characteristics. There is accordingly also a need to provide a process that can maintain the preferential nature of the solvent without interfering with the extraction process